Oil and gas wells are stimulated and re-stimulated in various ways to increase production of a flow of hydrocarbons from a completed well. With a newly completed well with a large reservoir and easily captured hydrocarbons, for example, the well may not require much or any stimulation techniques to produce an adequate flow of hydrocarbons from the well. Other wells, depending on composition or otherwise, may require more well stimulation to release the hydrocarbons from the subterranean formation containing the hydrocarbons.
In recent years, hydraulic fracturing has become a widely-used well stimulation technique to increase well production and access previously uncaptured hydrocarbons. Hydraulic fracturing involves hydraulically fracturing the subterranean formation with a pressurized liquid or carrier liquid, containing water, proppant (e.g., sand or man-made alternative), and/or chemicals, that is injected into a wellbore. Upon pressurizing the wellbore with the carrier liquid, the formation fractures or cracks and the carrier fluid can leave behind proppant, which allows the hydrocarbons to flow more freely through the fractures and into the wellbore to be recovered. In some instances, a downhole electric submersible pump may pump the hydrocarbons from the reservoir to overcome the hydrostatic head pressure of the hydrocarbons, or the hydrocarbons may flow freely up the wellbore without assistance.
As seen in FIG. 1, which is a side view of a horizontal drilling operation 100 utilizing hydraulic fracturing, a pressurized liquid 102 may cause multiple fractures 104 within the subterranean formation 106. Fractures 104 formed by the pressurized liquid 102 can be of varying sizes. Accordingly, larger fractures or pore volumes 108 may cause a lower stress zone 110 within the formation such that upon stimulation and re-stimulation of the well the carrier liquid 102 tends to concentrate in these lower stress zones 110. These lower stress zones 110 can be caused by hydrocarbon depletion, lower pore pressure, and/or higher permeability of the reservoir 106. Permeability of the reservoir can, in part, depend on the extensiveness of fractures and/or pores, and the interconnectivity of the fractures and/or pores that create pathways for hydrocarbons to flow. As a result of the lower stress zones, the hydrocarbons are more likely to flow through these larger fractures or pore volumes 108, and/or those with interconnectivity, until depletion. The fractures and/or pore volumes 104 of finer sizes 112 and/or those lacking interconnectivity tend to be concentrated in higher stress zones 114 such that the carrier liquid 102 is less likely to effectively hydraulically fracture those higher stress zones and thus influence the flow of hyrdrocarbons in these regions upon stimulation or re-stimulation. This is in part, because the pressure of the carrier liquid 102 is generally evenly distributed along the wellbore in the treated area such that the carrier liquid 102 remains concentrated in the lower stress zones 110 rather than the higher stress zones 114. The higher stress zones 114, in contrast to the lower stress zones 110, can be caused by higher pore pressure, ineffective hydraulically fractured regions, lower permeability of the reservoir 106, or generally less depleted portions of the reservoir 106. As such, the carrier liquid 102 tends to not affect the higher stress zones 114, which may contain hydrocarbons, unless additional systems and methods are employed.
In subsequent well treatments or in initial well treatments, diverter systems may be used to divert the carrier liquid 102 from the lower stress zones 110, which may be depleted from previous treatments, to the previously un-accessed, higher stress zones 114. Diverting the carrier liquid 102 into these higher stress zones 114 may be difficult over large areas of the wellbore and reservoir for a number of reasons. In new wells, the difficulty may be due to differences in stresses from different lithologies or from different reservoir characteristics along the well. Differences in stress can be due to natural in-situ stress conditions or man-made activities such as well stimulation or depletion of fluids. In previously stimulated wells, the difficulty may be due to adequately blocking the fractures and/or pore volume 108 in the lower stress zones 110 such that the carrier liquid 102 pressurizes the fractures 112 of the higher stress zones 114. Diverter systems include the use of particulates (e.g., polymers) and chemical diverters within the carrier liquid 102, among other methods, to block either the wellbore or the formation near the wellbore so that a portion of the carrier liquid 102 may be diverted to the fractures 112 in the higher stress zones 114 and also create new fractures in the higher stress zones.